1. Field of the Invention
The present invention relates to a method and apparatus for determining the actual porosity of strata being drilled using measuring-while-drilling techniques.
2. Description of the Prior Art
The search for hydrocarbons beneath the earth's surface requires a detailed knowledge of the structure of the various strata penetrated in order to evaluate the potential commercial value of the raw material which can be withdrawn from the strata. One of the most important pieces of data is the porosity of the strata which gives an indication of the void space in a layer which can be filled with gas or oil. There have been several techniques developed to measure the porosity of the formation surrounding a borehole. One technique employs a tool carrying an acoustic transmitter with one or more acoustic receivers spaced from the transmitter. The velocity of sound transmitted through the formation from the transmitter to the receivers is measured. Its reception is related to the porosity, since sound travels faster in less porous rocks than in fluid-filled pore spaces in earth formations. Another technique involves the use of gamma ray sources and at least one detector spaced therefrom to measure the electron density of the earth formations by gamma ray scattering. This technique leads to an inferential measurement of the porosity of the formation. A further known technique employs a neutron source and either a neutron or gamma ray detector sensitive to low energy, or thermalized, neutron density. Hydrogen is the principle agent responsible for the slowing down of neutrons emitted into earth formations. Therefore, in a formation containing a larger amount of hydrogen than is present in low porosity formations, the neutron distribution is more rapidly slowed down and is contained in the area of the formation near the source. Thus, the counting rates in remote thermal neutron sensitive detectors located several inches or more from the source will be suppressed. In lower porosity formations which contain little hydrogen, the source neutrons are able to penetrate further. Thus, the counting rates in the detector or detectors are increased.
The latter of the above techniques can use the teachings of U.S. Pat. No. 3,566,177 in which the porosity, commonly referred to as the "neutron porosity," derived from a neutron-neutron logging tool may be compared with the value of porosity, commonly referred to as the "density porosity," derived from a gamma-gamma formation density logging tool of the type disclosed in U.S. Pat. No. 3,321,625, in order to detect the presence of hydrocarbon gas in a formation.
Porosity measurements are most often performed by dual detector neutron porosity wireline logging tools provided with a neutron emitting source that irradiates the formation being studied. The tool typically is forced against one side of the borehole wall by laterally extending arms. The resulting neutron population is sampled by a pair of neutron detectors spaced at different distances from the neutron source. A tool of this type is disclosed in U.S. Pat. No. 3,482,376. If a two-detector measurement is made at a sufficient distance from the source, the effect of the borehole size and tool standoff are minimized by taking the ratio of the counting ranges. A function former or equivalent system then conveniently converts the ratio into a signal that represents otherwise uncorrected formation porosity. Unwanted contributions to the "ratio porosity" may include contributions from elements of the environment of the investigation such as the tool standoff, borehole size, mud weight, mud cake thickness, borehole salinity, formation salinity, etc. Correction for these environmental effects is subsequently conveniently accomplished in a separate operation by reference to a plurality of log interpretation charts which are readily available. Such an interpretation of logging results is obviously cumbersome and a hindrance to on-site interpretation of logging results. This is also a procedure which cannot be carried out while drilling.
Most commercial dual detector neutron logging has been accomplished with thermal neutron detectors due to the fact that reasonable counting rate statistics are obtainable at source detector spacings which yield values of porosity that are not too badly degraded by borehole environmental effects. Because the measurement of porosity is based on the detection of thermal neutrons, the presence of thermal neutron absorbing elements in the formation or the borehole complicates the interpretation of the results. Such elements in the formation are commonly associated with clay and/or salt water. It is known that information on clay types can be derived by means of logging tools that detect natural radioactivity. Unfortunately, the elements responsible for the natural radioactivity of clay are not the same as the thermal absorbers that interfere with the neutron logging tool. The importance of the influence of thermal neutron absorbers in a borehole or formation becomes apparent when it is understood that the comparison of "density porosity" with "neutron porosity", in order to obtain an indication of hydrocarbon gas, becomes suspect where there are thermal neutron absorbers in the formation.
The prior art technique of inferring the true porosity from measurements made with at least two different kinds of porosity sensors are discussed in Fundamentals of Formation Evaluation by Donald P. Helander, OGCI Publications, Tulsa, in combination with any of the Dresser or Schlumberger standard log interpretation manuals. One of the most common ways of doing this is to cross-plot porosity derived from gamma-gamma density measurements with porosity derived from a neutron porosity measurement.
A gamma-gamma density sensor measures only electron density. Its configuration is similar to that of a neutron porosity sensor, but the neutron source is replaced by a source of gamma rays and the detectors are gamma ray sensitive. Gamma rays lose energy in the formation through a number of mechanisms. For the range of energies used in a gamma-gamma density sensor, the primary mechanism of energy loss is scattering of the electrons, which is known as Compton scattering. Generally, densities increase with atomic number. Thus, as the density of the medium increases, so does the electron density. Therefore, the energy loss of gamma rays and scattering through a dense medium is greater than for scattering through a light medium. By monitoring the flux of gamma rays at some position uphole from the source, one can determine the electron density of the formation. As the density of a formation increases, the observed flux decreases. Porosity is derived from such density measurements by estimating the true density of the formation matrix, i.e. the rock making up the formation, and the true density of the fluids in the formation.
If there is gas in a formation, a gamma-gamma density derived porosity will tend to be high, while a neutron porosity measurement will tend to be low. A cross plot of the two logs thus serves as an indicator of the presence of gas. There are, however, a number of difficulties. The most common of these problems involves shale because shales contain a large amount of bound water, and the porosities of shale appear to be typically about 40% when measured by a porosity sensor. In fact, they typically have a low porosity.
The presence of shales can be distinguished on the basis of readings of natural gamma ray background; the shales are more radioactive than clean sands. Likewise, the percentage of shale in a sand can be estimated from the natural gamma ray background. The shale percentage can be used with the density derived porosity and the neutron porosity measurements to provide an indication of gas saturation. It will often happen that the shale volume as estimated using the natural gamma background is larger than the shale volume estimated using coordinates established in the cross plot. The reduced shale volume observed in the cross plot is due to the presence of gas and can be compensated for by appropriate adjustment of the graph interpretation.
A big drawback of all of the prior art thus far discussed is the fact that it cannot be used during the drilling operation. Instead, the drilling operation must be stopped, the drill string withdrawn and a wireline tool lowered in the borehole to take the various measurements. This is a time consuming and therefore very costly procedure.